Without limiting the scope of the present invention, its background will be described with reference to producing fluid from a subterranean formation, as an example.
After drilling each of the sections of a subterranean wellbore, individual lengths of relatively large diameter metal tubulars are typically secured together to form a casing string that is positioned within each section of the wellbore. This casing string is used to increase the integrity of the wellbore by preventing the wall of the hole from caving in. In addition, the casing string prevents movement of fluids from one formation to another formation. Conventionally, each section of the casing string is cemented within the wellbore before the next section of the wellbore is drilled. Accordingly, each subsequent section of the wellbore must have a diameter that is less than the previous section.
For example, a first section of the wellbore may receive a conductor casing string having a 20-inch diameter. The next several sections of the wellbore may receive intermediate casing strings having 16-inch, 13⅜-inch and 9⅝-inch diameters, respectively. The final sections of the wellbore may receive production casing strings having 7-inch and 4½-inch diameters, respectively. Each of the casing strings may be hung from a casing head near the surface. Alternatively, some of the casing strings may be in the form of liner strings that extend from near the setting depth of previous section of casing. In this case, the liner string will be suspended from the previous section of casing on a liner hanger.
Once this well construction process is finished, the completion process may begin. The completion process comprises numerous steps including creating hydraulic openings or perforations through the production casing string, the cement and a short distance into the desired formation or formations so that production fluids may enter the interior of the wellbore. In addition, the completion process may involve formation stimulation to enhance production, gravel packing to prevent sand production and the like. The completion process also includes installing a production tubing string within the well that extends from the surface to the production interval or intervals. Unlike the casing strings that form a part of the wellbore itself, the production tubing string is used to produce the well by providing the conduit for formation fluids to travel from the formation depth to the surface.
Typically, a production packer is run into the well on the production tubing string. The purpose of the packer is to support production tubing and other completion equipment, such as a screen adjacent to a producing formation, and to seal the annulus between the outside of the production tubing and the inside of the well casing to block movement of fluids through the annulus past the packer location. Conventionally, the packer is provided with anchor slips having opposed camming surfaces which cooperate with complementary opposed wedging surfaces, whereby the anchor slips are radially extendible into gripping engagement against the interior of the well casing in response to relative axial movement of the wedging surfaces.
The packer also carries annular seal elements which are expandable radially into sealing engagement against the interior of the well casing in response to axial compression forces. The longitudinal movement of the packer components required to set the anchor slips and the sealing elements may be produced either hydraulically or mechanically.
After the packer has been set and sealed against the well casing, this sealing engagement will typically remain even upon removal of the hydraulic or mechanical setting force. In fact, it is essential that the packer remain locked in its set and sealed configuration such that it can withstand hydraulic pressures applied externally or internally from the formation and/or manipulation of the production tubing string and service tools without unsetting or interrupting the seal.
It has been found, however, that to provide the required sealing and gripping capabilities, conventional packers have become quite complex. In addition, it has been found that due to the complexity of conventional packers, the cost of conventional packers is quite high. Further, it has been found that even with the complexity of conventional packers, some conventional packers fail to provide the necessary sealing and/or gripping capability after installation.
A need has therefore arisen for a system and method for creating a fluid seal between production tubing and well casing that does not require a complex conventional packer. A need has also arisen for such a system and method that are capable of reducing the cost typically associated with manufacturing a conventional packer. Further, a need has arisen for such a system and method that provide for improved sealing and gripping capabilities upon installation.